Methods and compositions for delayed release of chemicals and particles

ABSTRACT

Agents, chemicals and particles may be controllably released at remote locations, such as pre-selected or predetermined portions of subterranean formations, by binding or associating or trapping them with an association of micelles formed by a viscoelastic surfactant (VES) in an aqueous base fluid to increase the viscosity of the fluid. An internal breaker within the association of micelles disturbs the association of micelles at some later, predictable or predetermined time thereby reducing the viscosity of the aqueous viscoelastic treating fluid and releasing the agent, chemical or particle at a predetermined or selected location.

CROSS-REFERENCES TO RELATED APPLICATIONS

This application is a divisional patent application of U.S. patentapplication Ser. No. 12/404,723 filed Mar. 16, 2009, which issued on May12, 2015 as U.S. Pat. No. 9,029,299, which in turn claimed the benefitof U.S. Provisional Patent Application No. 61/037,179 filed on Mar. 17,2008, and is a continuation-in part of U.S. patent application Ser. No.11/679,018 filed on Feb. 26, 2007, issued May 25, 2010 as U.S. Pat. No.7,723,272 and is a continuation-in part of U.S. patent application Ser.No. 11/755,581 filed on May 30, 2007, issued Jun. 23, 2009 as U.S. Pat.No. 7,550,413, which in turn claims the benefit of U.S. ProvisionalPatent Application No. 60/815,693 filed on Jun. 22, 2006, and is acontinuation-in part of U.S. patent application Ser. No. 11/125,465,filed on May 10, 2005, issued Mar. 18, 2008 as U.S. Pat. No. 7,343,972,which in turn claims the benefit of U.S. Provisional Patent ApplicationNo. 60/570,601 filed May 13, 2004; all of which are incorporated hereinby reference in their entireties.

TECHNICAL FIELD

The present invention relates to aqueous, viscoelastic fluids usedduring hydrocarbon treatment operations, and more particularly relates,in one non-limiting embodiment, to methods and compositions for delayeddelivery of particles, chemicals and other agents at remote locationssuch as downhole to a subterranean reservoir.

BACKGROUND

Hydrocarbons such as oil, natural gas, etc., may be obtained from asubterranean geologic formation, e.g., a reservoir, by drilling a wellthat penetrates the hydrocarbon-bearing formation. This provides apartial flowpath for the hydrocarbons to reach the surface. In order foroil to be produced, that is travel from the formation to the well bore(and ultimately to the surface), there must be a sufficiently unimpededflowpath from the formation to the well bore. Unobstructed flow throughthe formation rock (e.g., sandstone, carbonates) is possible when rockpores of sufficient size and number are present for the oil to movethrough the formation.

However, as is becoming more generally known, greater effort and variedapproaches must be undertaken to produce hydrocarbons since therelatively easier to produce subterranean formations have generally beenfound. Thus, the oil and gas industry is looking at producinghydrocarbons from subterranean formations where recovering thehydrocarbons is more difficult and requires many steps, including theintroduction and placement of various components, additives and agentsat relatively precise locations downhole.

One such more complicated process involves hydraulically fracturing thesubterranean formation—literally breaking or fracturing a portion of thestrata surrounding the wellbore. The development of suitable fracturingfluids to provide the necessary hydraulic force is a complex art becausethe fluids must simultaneously meet a number of conditions. For example,they must be stable at high temperatures and/or high pump rates and highshear rates which can cause the fluids to degrade and prematurely settleout the proppant before the fracturing operation is complete. Variousfluids have been developed, but most commercially used fracturing fluidsare aqueous based liquids which have either been gelled or foamed. Whenthe fluids are gelled, typically a polymeric gelling agent, such as asolvatable polysaccharide is used, which may or may not be crosslinked.The thickened or gelled fluid helps keep the proppants within the fluidduring the fracturing operation.

While polymers have been used in the past as gelling agents infracturing fluids to carry or suspend solid particles in the brine, suchpolymers require separate breaker compositions to be injected to reducethe viscosity. Further, the polymers tend to leave a coating on theproppant even after the gelled fluid is broken, which coating mayinterfere with the functioning of the proppant. Studies have also shownthat “fish-eyes” and/or “microgels” present in some polymer gelledcarrier fluids will plug pore throats, leading to impaired leakoff andcausing formation damage. Conventional polymers are also either cationicor anionic which present the disadvantage of likely damage to theproducing formations.

Aqueous fluids gelled with viscoelastic surfactants (VESs) are alsoknown in the art. VES-gelled fluids have been widely used asgravel-packing, frac-packing and fracturing fluids because they exhibitexcellent rheological properties and are less damaging to producingformations than crosslinked polymer fluids. VES fluids arenon-cake-building fluids, and thus leave no potentially damaging polymercake residue. However, the same property that makes VES fluids lessdamaging tends to result in significantly higher fluid leakage into thereservoir matrix, which reduces the efficiency of the fluid especiallyduring VES fracturing treatments. It would thus be very desirable andimportant to discover and use fluid loss agents for VES fracturingtreatments in high permeability formations.

Many techniques and compositions are known to introduce chemicals,particles and other agents on a delayed release downhole, not only forpurposes of fracturing, but for other reasons, including, but notlimited to reducing fluid loss (as mentioned), breaking the gelledfluid, inhibiting scale, inhibiting corrosion, inhibiting hydrateformation, stimulation treatments (e.g. with acids), for cementing, forremedial purposes, etc. Various methods of keeping the chemical,particle or other agent in a form that is ineffective or preserved untildelivery or release at the proper locations downhole includemicroencapsulation, macroencapsulation, incorporation within an emulsionor multiple emulsion, and the like. It would be desirable if othertechniques besides these could be devised to provide an alternative orimproved downhole delayed agent delivery system.

SUMMARY

There is provided, in one form, a method for delayed treating of asubterranean formation with an agent that involves injecting an aqueousviscoelastic surfactant treating fluid through a wellbore to thesubterranean formation, particularly at a predetermined location, innon-limiting examples, in a fracture or at a particular zone. Theaqueous viscoelastic treating fluid may include, but is not necessarilylimited to, an aqueous base fluid, a viscoelastic surfactant (VES)gelling agent present in an amount effective to form an association ofmicelles that increases the viscosity of the aqueous viscoelasticsurfactant treating fluid, one or more internal breakers within theassociation of micelles, and the agent within the association ofmicelles. The method further involves breaking the association ofmicelles with the internal breakers to reduce the viscosity of theaqueous viscoelastic surfactant treating fluid and to deliver the agentat the predetermined location, and thus contact and/or treat thesubterranean formation.

There is further provided in another non-limiting embodiment an aqueousviscoelastic treating fluid that includes an aqueous base fluid, a VESgelling agent in an amount effective to form an association of micellesthat increases the viscosity of the aqueous viscoelastic surfactanttreating fluid, at least one internal breaker within the association ofmicelles, and an agent within the association of micelles. The agent mayinclude, but is not necessarily limited to, fluid loss control agents,bacteria, bacteria nutrients, biocides, enzyme polymer breakers,oxidative polymer breakers, microencapsulated chemicals,macroencapsulated chemicals, nanoencapsulated chemicals, scaleinhibitors, gas hydrate inhibitors, corrosion inhibitors, stimulationchemicals, remedial cleanup agents, water-block removal agents, scaleremoval agents, fine migration control agents, and combinations thereof.The aqueous viscoelastic surfactant treating fluid may also include atemperature stabilizer and/or a viscosity stabilizer.

In particular, in the case of the fluid loss control agents (e.g. MgOand/or Mg(OH)₂, and the like), these appear to help develop apseudo-filter cake of VES micelles by associating with them as well asions and particles (in one non-restrictive explanation) to produce anovel and unusual viscous fluid layer of pseudo-crosslinked elongatedmicelles on the wellbore and/or reservoir face that limits further VESfluid leak-off for controlling the depth of treatment fluid penetrationand/or as a means to better direct and target the placement location ofthe treating fluid with the select agent or agents to be released.Additionally, the art may be further advanced by use of nanometer-sizedfluid loss control agents that also form a similar viscous fluid layerof pseudo-crosslinked micelles on the wellbore and/or formation facethat are equivalent to micron-sized fluid loss control agents herein incontrolling rate of VES fluid loss and placement location of thetreatment fluid, yet can be non-pore plugging and physically easier toproduce back with the VES fluid after a VES treatment. That is, theeffectiveness of the method is largely independent of the size of thefluid loss control agents. The use of MgO for fluid loss control alsohas utility over a broad range of temperature of about 70° F. to about400° F. (about 21° C. to about 204° C.).

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic illustration of a top view of a wellbore and ahydraulic fracture;

FIG. 2 is a schematic illustration of the top view of the wellbore andhydraulic fracture of FIG. 1 where the gray area indicates the placementof a delayed release treatment fluid with pseudo-crosslink fluidcontrol;

FIG. 3 is a schematic illustration of a cross-sectional, elevation viewof a hydraulic fracture around a wellbore; and

FIG. 4 is a schematic illustration of the cross-sectional, elevationview of the hydraulic fracture around a wellbore of FIG. 3 where thedelayed release treatment fluid is shown as a gray area;

FIG. 5 is a schematic, cross-sectional, perspective view of wellbore anda hydraulic fracture; and

FIG. 6 is a schematic, cross-sectional, perspective view of the wellboreand hydraulic fracture of FIG. 5 where the gray area indicates placementof a delayed release treatment fluid illustrating near complete coverageof the fracture section.

It will be appreciated that the Figures are schematic illustrationswhich are not to scale, and that not all features are in properproportion to more clearly illustrate certain features.

DETAILED DESCRIPTION

Methods and chemical compositions have been discovered for altering theproperties of viscoelastic surfactants (VESs) in aqueous fluids. It hasbeen further surprisingly found that this technology may be appliedtoward controlled, targeted release of particles, chemicals and otheragents over time, either relatively spontaneously or over a relativelylong term, when placed in the wellbore or downhole in a subterraneanreservoir.

A specific method is primarily the temporary trapping or holding ofparticular agents (e.g. liquid chemicals or solid chemicals and otherparticles) within a VES fluid matrix and the delayed release of theparticular agents once or after a certain duration of time downhole byactivation of internal breaking agents that degrade the VES micellesstructure and fluid viscosity. The specific chemical properties to beconsidered in designing the delayed and controlled release of aparticular agent at a particular time and location include, but are notnecessarily limited to:

-   -   1. Appropriate viscosity to incorporate and temporarily trap the        agent to be released.    -   2. Appropriate type and amount of an internal breaker or        internal breakers.    -   3. The presence and proportion of a temperature stabilizer.    -   4. The presence and proportion of a viscosity stabilizer.    -   5. The presence and proportion of a VES micelle associating        fluid loss control agent or agents.

By “delayed release” is meant the release of the agent (e.g. chemical,particle, etc.) in a form and amount that is effective for their statedpurpose. That is, the agent is no longer prevented from being effectiveor active by being present in an association of micelles that impartincreased viscosity to the aqueous base fluid. These agents aretemporarily prevented or inhibited from being effective, or at leastsubstantially effective, by the presence and unique properties of theassociation of elongated micelles in which they are present.

Liquids gelled with polymers form polymeric filter cakes on and withinthe formation which can result in damage to the formation when thepolymeric filter cakes are incompletely or only partially removed priorto hydrocarbon production. This damage may result in reduced productionof hydrocarbons. In contrast, viscoelastic type surfactants generateviscosity in aqueous fluids by forming unique elongated micellearrangements. These unique arrangements have often been referred to asworm-like or rod-like micelles structures. The increase in viscosity isbelieved due to the entanglement of the worm-like or elongated micelles.Further, it is this interaction, entanglement or association of micellesthat carries the agent and keeps the agent from becoming activeprematurely, in one non-limiting explanation herein. Additionally, VESgelled aqueous fluids may exhibit very high viscosity at very low shearrates and under static conditions, and this fluid property can befurther enhanced by the addition of select particles that associate themicelles together into a stronger network or a more connected network,which further limits the rate of agent release until the internalbreaker degrades the viscous elongated micelle structures intonon-viscous spherical micelle structures. It has been found thatgenerally VES fluids do not damage formations to the extent that polymergelled fluids do.

In the non-restrictive embodiment of placing a fluid loss control agent,the aqueous fluid is viscosified with a VES having an internal breakerso that the agent to be released is concentrated on the wellbore or on afracture face as the desired location of release. A unique character ofthis method is that the VES micelles associate with one another in theaqueous fluid, and the associated micelles incorporate the agent andinternal breakers therein (and other components). The VES viscosity isan important property used to place the agent to a desired location, andone or more internal breakers are used for quicker, delayed, orotherwise controlled release of the agent, where little to no formationdamage occurs with this delay composition; that is, the viscoelasticsurfactant viscosified fluid, when broken by the internal breakingagents, will have brine-like fluid viscosity and is easily and readilyproducible from the subterranean formation and will leave little to noformation permeability damage.

Agents that may be released include, but are not necessarily limited to,fluid loss control agents, bacteria, bacteria nutrients, biocides,preservatives, enzyme polymer breakers, oxidative polymer breakers,polymer breaker enhancers, chelating agents, microencapsulatedchemicals, macroencapsulated chemicals, nanoencapsulated chemicals,fertilizers, zeolites, clays, pigments, inorganic minerals, inorganicflakes, ceramics, cement, shells, waxes, activated carbon, fullerenes,graphite, metals, metallic ions and complexes, resins, natural oils,refined oils, synthetic oils, fatty acids, proteins, amino acids,siloxanes, organic acids, polymerized organic acids, natural polymers,derivatized polymers, synthetic polymers, salts, sugars, water wettingsurfactants, oil wetting surfactants, emulsifying agents, demulsifyingagents, anti-oxidants, oxygen scavengers, meta-silicates, amines, pHbuffers, friction reducers, clay inhibitors, scale inhibitors, gashydrate inhibitors, corrosion inhibitors, paraffin inhibitors,stimulation chemicals, production chemicals, remedial cleanup agents,water-block removal agents, scale removal agents, diverting agents, finemigration control agents, and the like and combinations thereof. Asdescribed herein, microencapsulation and microcapsules are definedherein as concerning encapsulated materials where the diameter of themicrocapsule is 100 microns down to 1000 nanometers. Macroencapsulationinvolves the encapsulation of materials where the diameter of themacrocapsule is greater than 100 microns. Nanoencapsulation andnanocapsules refer to encapsulated materials where the diameter of thecapsule is 1000 nanometers or less. The maximum size of theparticulates, solids and other agents within the association of micellesis about 10 millimeters.

The delayed release chemicals may also be and involve other more commonagents in cementing, stimulation and production of subterraneanformation, including long horizontal reservoir drilling and completion,as well as for transporting and delayed release of agents along apipeline or other transmission conduit. In such applications, in the“parent” product (i.e. VES product gelled in an aqueous fluid), theagent may be complexed rather than suspended or solubilized, where agentrelease may be triggered upon the parent product use, and the like. Itis expected that this technology may have significant usage in otherindustries, including, but not necessarily limited to, agriculturalapplications, environmental remediation, waste disposal processes,cleaning processes, cosmetic uses, building and construction industry,mining industry, textile arts, and the like.

Aqueous Base Fluids and Viscoelastic Surfactants

In the methods and compositions described herein, for instance anaqueous fracturing fluid, as a non-limiting example, is first preparedby blending a VES into an aqueous base fluid. The aqueous base fluidcould be, for example, water, brine, aqueous-based foams orwater-alcohol mixtures. The brine base fluid may be any brine,conventional or to be developed which serves as a suitable media for thevarious components. As a matter of convenience, in many cases the brinebase fluid may be the brine available at the site used in the completionfluid, for a non-limiting example.

As noted, the aqueous fluids gelled by the VESs herein may optionally bebrines. In one non-limiting embodiment, the brines may be prepared usingsalts including, but not necessarily limited to, NaCl, KCl, CaCl₂,MgCl₂, NH₄Cl, CaBr₂, NaBr, sodium formate, potassium formate, and othercommonly used stimulation and completion brine salts. The concentrationof the salts to prepare the brines can be from about 0.5% by weight ofwater up to near saturation for a given salt in fresh water, such as10%, 20%, 30%, 40% and higher percent salt by weight of water. The brinecan be a combination of one or more of the mentioned salts, such as abrine prepared using NaCl and CaCl₂ or NaCl, CaCl₂, and CaBr₂ asnon-limiting examples.

The viscoelastic surfactants suitable for use herein may include, butare not necessarily limited to, non-ionic, cationic, amphoteric, andzwitterionic surfactants. Specific examples of zwitterionic/amphotericsurfactants include, but are not necessarily limited to, dihydroxylalkyl glycinate, alkyl ampho acetate or propionate, alkyl betaine, alkylamidopropyl betaine and alkylimino mono- or di-propionates derived fromcertain waxes, fats and oils. Quaternary amine surfactants are typicallycationic, and the betaines are typically zwitterionic. The thickeningagent may be used in conjunction with an inorganic water-soluble salt ororganic additive such as phthalic acid, salicylic acid or their salts.

Some non-ionic fluids are inherently less damaging to the producingformations than cationic fluid types, and are more efficacious per poundthan anionic gelling agents. Amine oxide viscoelastic surfactants havethe potential to offer more gelling power per pound, making it lessexpensive than other fluids of this type.

The amine oxide gelling agents RN⁺(R′)₂O⁻ may have the followingstructure (I):

where R is an alkyl or alkylamido group averaging from about 8 to 24carbon atoms and R′ are independently alkyl groups averaging from about1 to 6 carbon atoms. In one non-limiting embodiment, R is an alkyl oralkylamido group averaging from about 8 to 16 carbon atoms and R′ areindependently alkyl groups averaging from about 2 to 3 carbon atoms. Inan alternate, non-restrictive embodiment, the amine oxide gelling agentis tallow amido propylamine oxide (TAPAO), which should be understood asa dipropylamine oxide since both R′ groups are propyl.

Materials sold under U.S. Pat. No. 5,964,295 include CLEARFRAC™, whichmay also comprise greater than 10% of a glycol. This patent isincorporated herein in its entirety by reference. One preferred VES isan amine oxide. As noted, a particularly preferred amine oxide is tallowamido propylamine oxide (TAPAO), sold by Baker Oil Tools as SURFRAQ™VES. SURFRAQ is a VES liquid product that is 50% TAPAO and 50% propyleneglycol. These viscoelastic surfactants are capable of gelling aqueoussolutions to form a gelled base fluid. The additives herein may also beused in DIAMOND FRAQ™ which is a VES system, similar to SURFRAQ, whichcontains VES breakers sold by Baker Oil Tools.

The amount of VES included in the treating fluid depends on the type ofapplication. For hydraulic fracturing treatments, the concentration ofVES product to use is related to generating, creating or producingenough fluid viscosity to control the rate of fluid leak off into thepores of the fracture, which is also dependent on the type and amount offluid loss control agent used, and both work together to improve fluidefficiency to develop the optimum size and geometry of the fracturewithin the reservoir for enhanced reservoir production of hydrocarbonsand to also keep the chemicals, particles (e.g. proppant or otherparticles) and/or other agent complexed, suspended or viscosity trappedtherein during the fluid injecting step. For remedial treatments, suchas removal of residual crosslinked polymer filtercake typically leftwithin a hydraulic fracture after a crosslinked polymer fluid fracturingtreatment, the distribution of an enzyme or oxidative polymer breakeragent within the damaged hydraulic fracture can be significantlyimproved by using a VES-based treating fluid containing a moderate tohigh amount of VES product in combination with a VES micelle associatingfluid loss agent. The micelle associating agent allows the developmentof pseudo-filtercake to: 1) reduce the amount of treating fluid leak-offaway from the fracture; and 2) keep more treatment fluid within thehydraulic fracture and thereby significantly improve the distribution ofthe treating fluid containing polymer breaker. For a treatment to placeclay stabilizer within a producing formation to reduce the rate of finesmigration to the wellbore region, a low to moderate concentration of VESproduct in KCl brine will enhance the distribution of the claystabilizer within the treated reservoir. Stages of lower viscosityfollowed by higher viscosity VES-based treating fluid can also be usedto aid uniform distribution of the treating fluid with clay stabilizerin the reservoir. A similar treatment can be devised for placement offormation fines control agent or agents within the reservoir or morespecifically on proppant particles within a hydraulic fracture. Thus,depending on the application, the VES is added to the aqueous fluid inconcentrations ranging from about 0.5 to about 12.0% by volume of thetotal aqueous fluid (5 to 120 gallons per thousand gallons (gptg)). Inanother non-limiting embodiment, the range is from about 1.0 to about6.0% by volume VES product. In an alternate, non-restrictive form, theamount of VES ranges from about 2 to about 10 volume %.

Internal Breakers

In one particularly useful embodiment, the aqueous viscoelastic treatingfluid contains internal breakers. By the term “internal breakers” ismeant that the breaker is present in the fluid along with thecomposition causing the increase in viscosity, e.g. polymers or VESs, ascontrasted with adding the breaker to the gelled fluid separately, forinstance, injecting the breaker downhole after the gelled treatingfluid. Although in some non-limiting embodiments, polymers are not usedto increase the viscosity of the aqueous fluid, they may in someembodiments be used together with VESs. Conventional polymer breakersinclude, but are not limited to, enzymes, oxidizers, bacteria, acids,and combinations thereof.

The compositions of the treatment fluids herein may be a synergisticcombination of internal breakers with one or more high temperatureoptional stabilizers, optional viscosity enhancers, fluid loss controlagents, and mix water brines up to 14.4 ppg salinity (1.7 kg/liter),e.g. CaBr₂. The internal breakers described herein surprisingly work inthe presence of several types of VES micelle stabilizers, micelleviscosity enhancers, micelle fluid loss control agents, a wide range ofmix water salinity (including divalent ions like calcium and magnesium)for fluid temperature applications ranging from about 80° F. to about300° F. (about 27 to about 149° C.). The ability of these agents to worktogether by compatible mechanisms is remarkably unique and allows themany enhanced VES fluid performance properties to be combined.

In polymer filter cake, most of breaker in the polymer fluid system isleaked-off into the formation matrix and leaves a high concentration ofpolymer in the cake (fracture). The breaker is not attached to orconnected with the polymer. In VES pseudo-filter cake, the internalbreaker appears to be contained or resident inside of VES micelles andthus goes wherever VES micelles go, in one non-limiting explanation. Thefluid loss control agents may work from about 80° F. to about 300° F.(about 27 to about 149° C.). A wide range of particle types andproperties have been found of utility to improve the performance of theVES treating fluid, which includes, but is not necessarily limited to,surface adsorption, crystal surface charges, piezoelectric andpyroelectric particles, and nano-sized particle properties andtechnology. Additionally, the synergistic use of internal breakers withthe pseudo-filter cake has been discovered to allow the pseudo-filtercake to be readily degraded into an easily producible broken VES fluid.Another improved performance feature is how the fluids herein, a portionof which may inevitably leak-off into the pores of the reservoir duringa treatment, can carry with it internal breaker that converts the VESfluid into an easily producible or flowable fluid without the need forcontacting reservoir hydrocarbons and which also delivers the agentdownhole at a particular time and thus a particular place. Contact of aVES-gelled aqueous fluid with reservoir hydrocarbons is one method ofbreaking the viscosity of these fluids. The methods and fluids hereinare significant improvements over conventional methods and compositions,which, without contacting hydrocarbons, exhibit very high viscosity atvery low shear rates, such as 2000 cps or more at 1 sec shear rate. Thevery high viscosity of VES fluids at very low shear rates makes theleaked-off VES fluid within the pores of the formation require higherreservoir pressure in order to move and remove (clean up) the fluidwithin the reservoir matrix. Laboratory core clean-up tests have shownthat very little pressure and time is required to remove internallybroken VES from the pore matrix of Berea cores as compared to VES fluidswithout an internal breaker.

A viscoelastic surfactant-internal breaker aqueous fluid systemcontaining viscosity enhancers, VES stabilizers for high temperature,and fluid loss control agents and methods for using the systems fordelivering agents relatively precisely to subterranean formationspenetrated by a well bore have been discovered. A viscous gel starts todevelop when the viscoelastic surfactant (VES) is mixed with an aqueousbase fluid. A salt or other counterion may be used in the aqueous fluidcontaining VES to help promote viscous micelle formation. The VES-basedfracturing fluid is pumped in one or more sequential stages. The stagesof viscoelastic surfactant gelled fluid (that contains the mineral oiland/or fish oil, transition metal ion source, saponified fatty acid,unsaturated or saturated fatty acid or other internal breaker, e.g.)maintains a high viscosity prior to fracturing and other treating fluidapplications and eventual breaking (viscosity reduction) of the fluidthrough action of the breaker and thus delivery of the agent. Theviscosity of the VES gelled fluid is particularly improved, increased orenhanced, particularly at low shear rates, by the presence ofparticulate viscosity enhancers. One non-limiting example of aparticulate viscosity enhancer is nano-size ZnO particles used at 0.05to 0.1% by weight of VES treating fluid. In another non-limitingexample, the fluid viscosity can be improved up to ten-fold compared toVES fluid without particulate viscosity enhancer.

The rate of fluid leak-off during a treatment is also significantlyreduced by the presence of particulate fluid loss control agents.Further, the viscosity stability of the VES-gelled fluid may be improvedor enhanced by the presence of particulate high temperature viscositystabilizing agents. The viscosity enhancers, viscosity stabilizers, andfluid loss control agents, further improve the ability of the VES-basedaqueous fluid to place agents in select or predetermined locationswithin the reservoir, and each work by a mechanism that does not inhibitthe activity or mechanism of the other. In one non-limiting example, thepresence of a high temperature viscosity stabilizer does not inhibit theactivity of the internal breakers. In another non-limiting example, thepresence and activity of a fluid loss control agent does not inhibit thebreaking activity of an internal breaker. After completion of thepumping treatment and shut-in of the well, the internal breaker (e.g.mineral oil and/or fish oil) breaks the viscous gel, i.e. lowers theviscosity of the fracturing fluid readily and easily in the presence ofthe viscosity stabilizers, viscosity enhancers, and the like. Theinternally broken VES fluid is very easy to flow back with the producingfluid, leaving little or no damage to the formation. Very littlereservoir pressure and time is required to produce and clean up thebroken VES fluid. No reliance on reservoir hydrocarbons is required tocontact the VES fracturing fluid and reduce its viscosity, and thusrelease the agent at a time later than injection through the wellbore.Because of their nanometer size and the minute amount used, theparticulate viscosity enhancers and stabilizers are also readilyproducible and will readily clean-up and flowback with the broken VESfluid, leaving little to no particulate damage to the formation.

As noted, aqueous fluids gelled with viscoelastic surfactants have beenpreviously used in wellbore completions, such as hydraulic fracturing,without the use of an internal breaker system, and typically rely onexternal downhole conditions for the VES-gelled fluid to break, such asdilution with reservoir brine and more importantly gel breaking throughinteraction with reservoir hydrocarbons during production of suchreservoir fluids to the surface. However, reliance on external downholeconditions has showed instances where unbroken or poorly broken VESfluid remains within the reservoir after a VES fluid treatment and hasimpaired hydrocarbon production. There are aqueous fluids gelled withviscoelastic surfactants that are known to be “broken” or have theirviscosities reduced, although some of the known breaking methods utilizeexternal clean-up fluids as part of the treatment design (such as pre-and post-flush fluids placed within the reservoir before and after wellcompletion treatments, such as conventional gravel packing and also“frac-packing”—hydraulic fracturing followed by gravel packingtreatment). There are other known methods, but they are relativelyslow—for instance the use of VES-gel breaking bacteria with fluidviscosity break times ranging from half a day up to 7 days. There hasevolved in the stimulation fluid art an industry standard need for“quick gel break”, but for VES-gelled fluids this has been asubstantially challenging problem. There needs to be a method forbreaking VES-gelled fluids that can be as easy, as quick, and aseconomic as breaking conventional polymeric fluids, in one non-limitingembodiment, using an internal breaker. At the same time, it is notdesirable to reduce the viscosity of the fluid, i.e. break the gel,immediately or essentially instantaneously. Of concern is the fact thanan unbroken VES fluid has exceptionally high viscosity at very low shearrate and static conditions which makes it difficult for reservoirhydrocarbons to contact all of the VES fluid and to displace it from thepores of a treated reservoir. This is particularly true for gasreservoirs and crude oil reservoirs that have heterogeneous permeabilitywith high relative permeability sections present.

New methods have been discovered to reduce the viscosity of aqueousfluids gelled with viscoelastic surfactants (i.e. surfactants thatdevelop viscosity in aqueous brines, including chloride brines, byformation of rod- or worm-shaped micelle structures). The new methodsremove the need or reliance on reservoir hydrocarbons to contact, break,and cleanup the viscoelastic fluid. The improvements will allowrelatively very quick breaks, such as within about 1 to about 16 hours,compared to using bacteria to break VES which takes at least 48 or morehours, and more typically 4 to 7 days. In another non-limitingembodiment the break occurs within about 1 to about 8 hours;alternatively from about 1 to about 4 hours, and in anothernon-restrictive version about 1 to about 2 hours. The breaker componentsherein can be used as an internal breaker, e.g. added to the gel afterbatch mixing of a VES-gel treatment, or added on-the-fly aftercontinuous mixing of a VES-gel treatment using a liquid additivemetering system in one non-limiting embodiment, or the components may beused separately, if needed, as an external breaker solution to removeVES gelled fluids already placed downhole. Internal breakers suitablefor the methods and compositions herein include, but are not necessarilylimited to, transition metal ion sources, reducing agent sources,chelating agent sources, alkali metal sources, alkaline earth metalsources, saponified fatty acids, mineral oils, hydrogenatedpolyalphaolefin oils, saturated fatty acids, unsaturated fatty acids andcombinations thereof. Bacteria may also be used alone or conjunctionwith these other internal breakers, although as noted, reducing theviscosity of VES gelled fluids with bacteria is relatively slow. The useof bacteria as a viscosity breaker for VES gelled fluids is described inU.S. Pat. No. 7,052,901 to Baker Hughes, incorporated herein in itsentirety by reference.

The internal breakers (e.g. mineral oils, hydrogenated polyalphaolefinoils, saturated fatty acids, polyunsaturated fatty acids, and the like)are not solubilized in the brine, since they are inherently hydrophobic,but rather interact with the VES surfactant worm-like micelle structuresinitially as dispersed microscopic oil droplets and thus form anoil-in-water type emulsion where the oil droplets are dispersed in the“internal phase” as a “discontinuous phase” of the brine medium/VESfluid which is the “outer phase” or “continuous phase”. Laboratory testshave shown that small amounts of unsaturated fatty acids, enough toeventually completely the break VES viscosity, will not spontaneouslydegrade VES viscosity upon individual association and dispersion withinthe VES micelles, but will become active to degrade VES viscosity uponactivation, such as auto-oxidation of the fatty acids to products thatdisrupt the elongated, “rod-like” or “worm-like” micelles.

Surprisingly and unexpectedly the method may employ one or more mineraloil (as a non-limiting example of a suitable breaker) as the breakingcomponent. This is surprising because, as previously discussed, theliterature teaches that contact of a VES-gelled fluid with hydrocarbons,such as those of the formation in a non-limiting example, essentiallyinstantaneously reduces the viscosity of the gel or “breaks” the fluid.By “essentially instantaneously” is meant less than one-half hour. Therate of viscosity break for a given reservoir temperature by the methodsdescribed herein is influenced by type and amount of salts within themix water (i.e. seawater, KCl, NaBr, CaCl₂, CaBr₂, NH₄CI and the like),presence of a co-surfactant (i.e. sodium dodecyl sulfate, sodium dodecylbenzene sulfonate, potassium laurate, potassium oleate, sodium laurylphosphate, and the like), VES type (i.e. amine oxide, quaternaryammonium salt, and the like), VES loading, the amount of breaker (e.g.mineral oil) used, the distillation range of the mineral oil, itskinematic viscosity, the presence of components such as aromatichydrocarbons, and the like.

It is important to add the lower molecular weight mineral oils after theVES product is added to the aqueous fluid. However, for higher molecularweight mineral oils, types like GLORIA® and HYDROBRITE® 200 fromCrompton Corporation, they may be added before, during or after the VESproduct addition. Mineral oil (also known as liquid petrolatum) is aby-product in the distillation of petroleum to produce gasoline. It is achemically inert transparent colorless oil composed mainly of linear,branched, and cyclic alkanes (paraffins) of various molecular weights,related to white petrolatum. Mineral oil is produced in very largequantities, and is thus relatively inexpensive. Mineral oil products aretypically highly refined, through distillation, hydrogenation,hydrotreating, and other refining processes, to have improvedproperties, and the type and amount of refining varies from product toproduct. Highly refined mineral oil is commonly used as a lubricant anda laxative, and with added fragrance is marketed as “baby oil” in theU.S. Most mineral oil products are very inert and non-toxic, and arecommonly used as baby oils and within face, body and hand lotions in thecosmetics industry. Other names for mineral oil include, but are notnecessarily limited to, paraffin oil, paraffinic oil, lubricating oil,base oil, white mineral oil, and white oil.

In one non-limiting embodiment the mineral oil is at least 99 wt %paraffinic. Because of the relatively low content of aromatic compounds,mineral oil has a better environmental profile than other oils. Ingeneral, the more refined and less aromatic the mineral oil, the better.In another non-restrictive version, the mineral oil may have adistillation temperature range from about 160 to about 550° C.,alternatively have a lower limit of about 200° C. and independently anupper limit of about 480° C.; and a kinematic viscosity at 40° C. fromabout 1 to about 250 cSt, alternatively a lower limit of about 1.2independently to an upper limit of about 125 cSt. Specific examples ofsuitable mineral oils include, but are not necessarily limited to,BENOL®, CARNATION®, KAYDOL®, SEMTOL®, HYDROBRITE® and the like mineraloils available from Crompton Corporation, ESCAID®, EXXSOL® ISOPAR® andthe like mineral oils available from ExxonMobil Chemical, and similarproducts from other mineral oil manufacturers. The ESCAID 110® andConoco LVT-200® mineral oils have been well known components ofoil-based drilling muds and the oil industry has considerable experiencewith these products, thus making them attractive choices. The mineraloils from ConocoPhillips Company with their high purity and high volumeuse within other industries are also an attractive choice.

It has been discovered in breaking VES-gelled fluids prepared inmonovalent brines (such as 3% KCl brine) that at temperatures belowabout 180° F. (82° C.) ESCAID® 110 works well in breaking VES-gelledfluids, and that at or above about 140° F. (60° C.) HYDROBRITE® 200works well. The use of mineral oils herein is safe, simple andeconomical. In some cases for reservoir temperatures between about 120°to about 240° F. (about 49° to about 116° C.) a select ratio of two ormore mineral oil products, such as 50 wt % ESCAID® 110 to 50 wt %HYDROBRITE® 200 may be used to achieve controlled, fast and completebreak of a VES-gelled fluid.

It has also been discovered that type and amount of salt within the mixwater used to prepare the VES fluid (such as 3 wt % KCl, 21 wt % CaCl₂,use of natural seawater, and so on) and/or the presence of a VES gelstabilizer (such as VES-STA 1 available from Baker Oil Tools) may affectthe activity of a mineral oil in breaking a VES fluid at a giventemperature. For example, ESCAID® 110 at 5.0 gptg will readily break the3 wt % KCL based VES fluid at 100° F. (38° C.) over a 5 hour period.ESCAID® 110 also has utility as a breaker for a 10.0 ppg CaCl₂ (21 wt %CaCl₂) based VES fluid at 250° F. (121° C.) when a VES stabilizer (2.0pptg VES-STA 1) is included. More information about using mineral oils,hydrogenated polyalphaolefin oils and saturated fatty acids as internalbreakers may be found in U.S. Pat. No. 7,347,266, incorporated byreference herein in its entirety.

In one non-limiting embodiment these gel-breaking products or breakerswork by rearrangement of the VES micelles from rod-shaped or worms-hapedelongated structures to spherical structures. The breaking componentsdescribed herein may also include the unsaturated fatty acid orpolyenoic and monoenoic components of U.S. Patent ApplicationPublication 2006/0211776, Ser. No. 11/373,044 filed Mar. 10, 2006,incorporated herein in its entirety by reference. In one non-limitingembodiment these unsaturated fatty acids (e.g. oleic, linoleic,linolenic, eicosapentaenoic, etc.) may possibly be used alone—in oilsthey are commonly found in (e.g. flax oil, soybean oil, etc.), and canbe provided as custom fatty acid blends (such as Fish Oil 18:12TG byBioriginal Food & Science Corp.)—or used together with the mineral oilsherein. In another non-limiting embodiment, natural saturatedhydrocarbons such as terpenes (e.g. pinene, d-limonene, etc.), saturatedfatty acids (e.g. lauric acid, palmitic acid, stearic acid, etc. fromplant, fish and/or animal origins) and the like may possibly be usedtogether with or alternatively to the mineral oils herein. In some casesit is preferred that the plant or fish oil be high in polyunsaturatedfatty acids, such as flax oil, salmon oil, and the like. The plant andfish oils may be refined, blended and the like to have the desiredpolyunsaturated fatty acid composition modified for the compositions andmethods herein. Other refinery distillates may potentially be used inaddition to or alternatively to the mineral oils described herein, asmay be hydrocarbon condensation products. Additionally, syntheticmineral oils, such as hydrogenated polyalphaolefins, and othersynthetically derived saturated hydrocarbons may be of utility topractice the methods herein.

In one non-limiting embodiment, the breaking or viscosity reduction istriggered or initiated or facilitated by heat. These mineral, plant, andanimal oils will slowly, upon heating, break or reduce the viscosity ofthe VES gel with the addition of or in the absence of any otherviscosity reducing agent. The amount of internal breaker (mineral oil,e.g.), needed to break a VES-gelled fluid may in some cases betemperature dependent, with less needed as the fluid temperatureincreases. For mineral oil, the kinematic viscosity, molecular weightdistribution, and amount of impurities (such as aromatics, olefins, andthe like) also appear to influence the rate in which a mineral oil willbreak a VES-gelled fluid at a given temperature. For unsaturated fattyacid oils the type and amount of unsaturation (i.e. double carbon bonds)appears to be the major influence on the rate at which the fatty acidoil will break the VES-gelled fluid at a given temperature. Once a fluidis completely broken at an elevated temperature and cooled to roomtemperature a degree of viscosity reheal may occur but in most cases norehealing is expected. The effective amount of mineral oil, plant oiland/or fish oil ranges from about 0.1 to about 20 gptg based on thetotal fluid, in another non-limiting embodiment from a lower limit ofabout 0.5 gptg, where “total fluid” means overall VES gelled fluid withall components of the particular embodiment. Independently the upperlimit of the range may be about 12 gptg based on the total fluid. (Itwill be appreciated that units of gallon per thousand gallons (gptg) arereadily converted to SI units of the same value as, e.g. liters perthousand liters, m³/1000 m³, etc.).

Controlled viscosity reduction rates can be achieved at a temperature offrom about 70° F. to about 400° F. (about 21 to about 204° C.), andalternatively at a temperature of from about 100° F. independently to anupper end of the range of about 280° F. (about 38 to about 138° C.), andin another non-limiting embodiment independently up to about 300° F.(149° C.). In one non-limiting embodiment, the fluid designer wouldcraft the fluid system in such a way that the VES gel would break at ornear the formation temperature to deliver the agent downhole at apredetermined or designed location.

In one non-limiting embodiment, fluid internal breaker design would bebased primarily on formation temperature, i.e. the temperature the fluidwill be heated to naturally in the formation once the acidizing,fracturing or other treatment is over. Fluid design may take intoaccount the expected duration or exposure of the fluid at formationtemperature during a treatment. There would generally be no additionaltemperature or heating the VES fluid would see or experience other thanoriginal reservoir temperature.

In another non-limiting example, a combination of internal breakers mayhave synergistic results, that is, the breaking profile of the fluidover time may be improved when two types of internal breakers are usedrather only one or the other. The use of mineral oil alone, like the useof polyenoic breaker alone, does not give the rate and degree ofviscosity reduction over time as does the combination of mineral oilwith polyenoic breaker. By using combinations of internal breakers, boththe initial and final break of the VES fluid may be customized, that is,have improved overall breaking performance. One breaker mechanism mayhelp speed up another breaker mechanism. Surprisingly, even with twointernal breaker mechanisms present in the VES fluid, the novelpseudo-filter cake with fluid loss control agent may show excellentfluid loss control.

It is sometimes difficult to specify with accuracy in advance the amountof the various breaking components that should be added to a particularaqueous fluid gelled with viscoelastic surfactants to sufficiently orfully break the gel, in general. For instance, a number of factorsaffect this proportion, including but not necessarily limited to, theparticular VES used to gel the fluid; the particular breaker used (e.g.mineral, plant, and/or fish oil, unsaturated fatty acid, etc.); thetemperature of the fluid; the downhole pressure of the fluid, thestarting pH of the fluid; and the complex interaction of these variousfactors. Nevertheless, in order to give an approximate idea of theproportions of the various breaking components to be used in the methodsherein, approximate ranges will be provided. In an alternative,non-limiting embodiment the amount of mineral oil that may be effectiveherein may range from about 5 to about 25,000 ppm, based on the totalamount of the fluid. In another non-restrictive version, the amount ofmineral oil may range from a lower end of about 50 independently to anupper end of about 12,000 ppm.

The use of transition metal ion sources as breakers for VES-gelledfluids is more fully described in U.S. Ser. No. 11/145,630 filed Jun. 6,2005, published as U.S. Patent Application Publication 2006/0041028,incorporated by reference herein in its entirety. Briefly, thetransition metal ion source used as an internal breaker may include atransition metal salt or transition metal complex, where the transitionmetal may be from Groups VA, VIA, VIIA, VIIIA, IB, IIB, IIIB, and IVB ofthe Periodic Table (previous IUPAC American Group notation). One or morechelating agents and/or one or more reducing agent sources may also beused in conjunction with the transition metal ion sources as breakingagents. In one non-limiting embodiment, the amount of transition metalion from the transition metal ion source ranges from about 0.01 to about300 ppm, based on the total fluid.

The use of saponified fatty acids as breakers for VES gelled aqueousfluids is more fully described in U.S. Ser. No. 11/372,624 filed Mar.10, 2006, published as U.S. Patent Application Publication 2006/0211775,incorporated by reference herein in its entirety. Briefly, thesaponified fatty acids are soap reaction products of a fatty acid withan alkaline compound selected from the group consisting of organicbases, alkali metal bases, alkaline earth metal bases, ammonium bases,and combinations thereof. The soap reaction products may be pre-formedprior to addition as an internal breaker, or may be formed in situ.Suitable fatty acids include, but are not limited to those found inplant oils and animal oils. Suitable alkali metal bases, alkaline earthmetal bases and ammonium bases include, but are not necessarily limitedto oxides and hydroxides of cations of the group including Na, K, Cs,Ca, Mg, Ba, Fe, Mn, Cu, Zn, Zr, Mo, V, Co, Al, Sn, NH₄, (CH₃)₄N, andmixtures thereof. Suitable organic bases include, but are notnecessarily limited to, diethanolamine, triethanolamine, choline basesand mixtures thereof. In one non-restrictive embodiment herein, theamount of saponified fatty acid that is effective as a viscosity breakerranges from about 50 to about 20,000 ppm based on the total viscoelasticsurfactant gelled fluid.

The use of the disclosed breaker systems is ideal for controllingviscosity reduction of VES based fracturing treating fluids. Thebreaking system may also be used for breaking gravel pack fluids,acidizing or near-wellbore clean-up fluids, loss circulation pill fluidscomposed of VES, drilling fluids composed of VES, targeted placement ofdelayed release agents, and for many other applications. The breakersystem may additionally work for foamed fluid applications (hydraulicfracturing, acidizing, and the like), where N₂ or CO₂ gas is used forthe gas phase. The VES breaking methods herein are a significantimprovement in that it gives breaking rates for VES based fluids thatthe industry is accustomed to with conventional polymer based fluids,such as borate crosslinked guar and linear HEC (hydroxyethylcellulose).Potentially more importantly, the use of these internal breaker systemsin combination with external downhole breaking conditions should helpassure that the agents (chemicals, particles, etc.) are deliveredrelatively precisely on a time-delayed basis at the downhole locationdesired.

In one non-limiting embodiment, the compositions herein will degrade thegel created by a VES in an aqueous fluid, by disaggregation orrearrangement of the VES micellar structure. However, the inventors donecessarily not want to be limited to any particular mechanism. Also, inanother non-restrictive version, the only component present in the VESgelled aqueous fluid that reduces viscosity is one of the internalbreakers described herein, or mixtures thereof. That is, a separatelyintroduced external breaker component introduced after the VES-gelledfracturing fluid is not used (e.g. various clean-up fluids). However,conditions (such as elevated temperature) and already existing chemicals(reservoir hydrocarbons) may be present when and where the internalbreakers are included, either intentionally or incidentally.

Fluid Loss Agents

It has been discovered that the addition of alkaline earth metal oxides,such as magnesium oxide, and alkaline earth metal hydroxides, such ascalcium hydroxide, to an aqueous fluid gelled with a VES improved thefluid loss of these brines. The fluid loss control agents herein arebelieved to be particularly useful in directing placement of VES-gelledfluids containing select agents to be used for well completion, remedialand/or stimulation. In another particularly useful application ofdirecting placement of VES-gelled fluid containing select agents is forlong horizontal completions, such as 4000 feet (1220 meters) or longerhorizontal wellbores where uniform coverage is often problematic usingconventional methods. The VES-gelled fluids may further compriseproppants or gravel, if they are intended for use as fracturing fluidsor gravel packing fluids, although such uses do not require that thefluids include proppants or gravel. In particular, the VES-gelledaqueous fluids have improved (reduced, diminished or prevented) fluidloss over a broad range of temperatures, such as from about 70 (about21° C.) to about 400° F. (about 204° C.); alternatively up to about 350°F. (about 177° C.), and in another non-limiting embodiment up to about300° F. (about 149° C.). Use of MgO and the like particles, as disclosedwithin U.S. Pat. No. 7,343,972 (incorporated herein by reference in itsentirety) is for high temperature stability of VES viscosity, andapplies for temperature applications above about 190° F. (about 88° C.).The use of MgO and the like particles for the fluid loss control hereinhas application and functionality to much broader temperature range,such as from about 70° F. to about 400° F. (about 21° C. to about 204°C.), and may be used in low salinity monovalent brines, such as 3% KCl.

The fluid loss control agents (e.g. MgO and/or Mg(OH)₂, and the like)appear to help develop a pseudo-filter cake of VES micelles byassociating with them as well as ions and particles (in onenon-restrictive explanation) to produce a novel and unusual viscousfluid layer of pseudo-crosslinked elongated micelles on the reservoirface that limits further VES fluid leak-off. Additionally, the art maybe further advanced by use of nanometer-sized fluid loss control agentsthat also form a similar viscous fluid layer of pseudo-crosslinkedmicelles on the formation face that are equivalent to micron-sized fluidloss control agents herein in controlling rate of VES fluid loss, yetcan be non-pore plugging and physically easier to produce back with theVES fluid after a VES treatment. That is, the effectiveness of themethod is largely independent of the size of the fluid loss controlagents.

Additionally, it has been discovered that the range in reservoirpermeability does not significantly control the rate of fluid leaked-offwhen the additives described herein are within a VES fluid. Thus, therate of leak-off in 2000 md reservoirs will be comparable to rate ofleak-off in 100 and 400 md reservoirs. This enhanced control in theamount of fluid leaked-off for higher permeability reservoirs alsoexpands the range in reservoir permeability to which the VES fluid maybe applied. The expanded permeability range may allow VES fluids to beused successfully within reservoirs with permeabilities as high as 2000to 3000 or more millidarcies (md). Prior VES-gelled aqueous fluids havereservoir permeability limitations of about 800 md, and even then theyresult in 2- to 4-fold volume of VES fluid leak-off rate as comparedwith the fluid loss control achievable with the methods and compositionsherein.

Prior art VES-gelled aqueous fluids, being non-wall-building fluids(i.e. there is no polymer or similar material build-up on the formationface to form a filter cake) that do not build a filter cake on theformation face, have viscosity-controlled fluid leak-off into thereservoir. By contrast, the methods and compositions herein use a fluidloss agent that associates with the VES micelle structures throughchemisorption or/and particle surface charge attraction, allowingpseudo-crosslinking of the elongated micelles to occur, in onenon-limiting explanation of the mechanisms at work herein. This uniqueassociation has been found to form a highly viscous layer ofcrosslinked-like VES fluid on the formation face, thus acting as apseudo-filter cake layer that limits and controls additional VES fluidfrom leaking-off into the reservoir pores. The pseudo-filter cake iscomposed of VES micelles that have VES surfactants with very lowmolecular weights of less than 1000. This is in contrast to anddifferent from polymeric fluids that form true polymer massaccumulation-type filter cakes by having very high molecular weightpolymers (1 to 3 million molecular weight) that due to their size arenot able to penetrate the reservoir pores, but bridge-off and restrictfluid flow in the pores.

The fluid loss agents herein associate with the VES micelles and as VESfluid is leaked-off into the reservoir a viscous layer of micelles andfluid loss control particles and/or ions accumulate on the formationface, thus reducing the rate of VES fluid leak-off. It has beendiscovered that particulate plugging of the reservoir pores is not themechanism of leak-off control or the mechanism that allows developmentof the viscous micelle layer. Tests using nanometer-sized fluid lossagents (where “nanometer-sized” is defined herein as on the order of10⁻⁹ to 10⁻⁸ meters), that have no potential to bridge or plug reservoirpores of 1 and or higher reservoir permeability, still develop theviscous micelle layer. These materials still have the same or similarleak-off control-rate profiles (i.e. rate of fluid leak-off over time)as the 1 to 5 micron size fluid loss control particles useful for thecompositions and methods herein that are larger. Thus, the size of thefluid loss agent is not a controlling and/or primary factor of methodsand compositions herein, that is, to control VES fluid leak-off rate.

The fluid loss control agents useful herein include, but are notnecessarily limited to, slowly soluble alkaline earth metal oxides oralkaline earth metal hydroxides, transition metal oxides, transitionmetal hydroxides, or mixtures thereof. In one non-limiting embodiment,the alkaline earth metal and transition metals in these additives mayinclude, but are not necessarily limited to, magnesium, calcium, barium,strontium, aluminum, zirconium, vanadium, molybdenum, manganese, iron,cobalt, nickel, palladium, copper, zinc, tin, antimony, titanium,combinations thereof and the like. In one non-restrictive version, thetransition metals such as copper, tin, nickel, and the like may be usedin relatively low concentration compared to or in combination with thealkaline earth metals. In one non-restrictive embodiment, the amount ofadditive ranges from about 2 to about 200 pounds per thousand gallons(pptg) (about 0.2 to about 24 kg/m³) based on the aqueous viscoelastictreating fluid. In another non-restrictive embodiment, the amount ofadditive may have a lower limit of about 6 pptg (about 0.7 kg/m³) andindependently an upper limit of about 80 pptg (about 9.6 kg/m³), and inanother non-restrictive version a lower limit of about 8 pptg (about 1kg/m³) and independently an upper limit of about 40 pptg (about 4.8kg/m³), and in still another non-limiting embodiment, a lower limit ofabout 10 pptg (about 1.2 kg/m³) and independently an upper limit ofabout 25 pptg (about 3 kg/m³).

The amount of transition metal oxides or transition metal hydroxides mayrange from about 0.0001 pptg (about 0.01 g/m³) independently to an upperlimit of about 4 pptg (about 0.45 kg/m³), and in another non-restrictiveversion from about 0.1 pptg (about 12 g/m³) independently up to about0.5 pptg (about 60 g/m³). In another non-limiting embodiment, theparticle size of the fluid loss control agents ranges between about 1nanometer independently up to about 0.2 millimeter. In anothernon-limiting embodiment, the particle size of the fluid loss controlagents ranges between about 4 nanometers independently up to about 74microns. The fluid loss control agents may be added along with the VESfluids. In another non-restrictive version the fluid loss control agentsmay have a surface area of between about 10 to about 700 square metersper gram (m²/g).

Delayed Release Agents

A chemical or biological agent (e.g. crosslinked polymer, acid, orbiocide, among others) that is a useful component of a completion,stimulation, remedial or workover fluid can, in certain cases, beundesirably neutralized or degraded before reaching the site at which itis to have its effect. Therefore, in certain instances, more of theagent is used in order to be effective and to compensate for agent thatis lost in delivering the agent to the site. Thus, there is a need for amore efficient way to deliver useful chemical and biological agents to adesired location in a well. In the methods and compositions herein,these and other agents may be present within the association of micellesand would not be spent, that is, would be kept from reacting or beingeffective until the fluid containing the association of micelles isdelivered downhole, or to some other remote location, where the gel isbroken with an internal breaker, the micelles dissociate, and the agentis delivered to a particular location at a point in time later ordelayed from its initial injecting into a well bore.

Such chemical or biological agents may include, but not necessarily belimited to, fluid loss control agents, oxidative polymer breakers,enzyme polymer breakers, polymer breaker enhancers, microencapsulatedchemicals, macroencapsulated chemicals, nanoencapsulated chemicals,fertilizers, zeolites, clays, pigments, inorganic minerals, inorganicflakes, ceramics, cement, shells, waxes, activated carbon, fullerenes,graphite, metals, metallic ions and complexes, resins, natural oils,refined oils, synthetic oils, fatty acids, proteins, amino acids,siloxanes, organic acids, polymerized organic acids, scale inhibitors,gas hydrate inhibitors, stimulation chemicals, production chemicals,pipeline chemicals, water treatment chemicals, mining chemicals,detergent chemicals, environmental remediation chemicals, remedialcleanup agents, water-block removal agents, crosslinkers, polymers,biocides, preservatives, corrosion inhibitors, corrosion dissolvers, pHmodifiers, metal chelators, metal complexors, antioxidants, wettingagents, polymer stabilizers, clay stabilizers, scale dissolvers, waxinhibitors, wax dissolvers, asphaltene precipitation inhibitors,waterflow inhibitors, sand consolidation chemicals, permeabilitymodifiers, foaming agents, diverting agents, microorganisms, nutrientsfor microorganisms, salts, sugars, water wetting surfactants, oilwetting surfactants, emulsifying agents, demulsifying agents,anti-oxidants, oxygen scavengers, meta-silicates, amines, frictionreducers, fines migration control agents, and the like. As previouslynoted, the delayed release agents may be solids or liquids. The delayedrelease agents may be oil-soluble, water-soluble and/or waterdispersible.

The aqueous treatment fluid can also contain other additives common tothe well service industry such as water wetting surfactants,non-emulsifiers and the like. In the methods and compositions herein,the base fluid may also contain additives which can contribute tobreaking the gel (reducing the viscosity) of the VES fluid.

In another non-limiting embodiment, the treatment fluid may containother viscosifying agents, other different surfactants, claystabilization additives, scale dissolvers, biopolymer degradationadditives, and other common and/or optional components.

Stabilizers

Additionally, select particulate fluid loss control agents herein mayoptionally be used at lower concentrations in the VES treating fluid ashigh temperature viscosity stabilizers; that is for stabilizing orsustaining the VES fluid viscosity at elevated fluid temperatures, suchas above 180° F. (82° C.). Suitable viscosity stabilizers include, butare not limited to, magnesium oxide, magnesium hydroxide, calcium oxide,calcium hydroxide, sodium hydroxide, and the like. The select viscositystabilizers may, in one non-limiting embodiment, have an averageparticle size of 500 nanometers or less, that is, to be preferably smallenough to be non-pore plugging and thereby will remain with the VESfracturing fluid wherever it goes during the treatment and duringflowback. More information about using these oxides and hydroxides ashigh temperature viscosity stabilizers may be found in U.S. Pat. No.7,343,972 and U.S. Patent Application Publication No. 2008/0051302 A1,both of which are incorporated by reference herein in their entirety.

The increased viscosity of aqueous fluids gelled with viscoelasticsurfactants (VESs) may also be maintained or stabilized by one or morestabilizers that are glycols and/or polyols. These glycols and polyolsmay stabilize the increased viscosity of VES-gelled fluids effectivelyover an increased temperature range, such as from about ambient to about300° F. (about 149° C.). Even though some VESs used to increase theviscosity of aqueous fluids contain a glycol solvent, the use, additionor introduction of the same or different glycol or a polyol, possibly ofincreased purity, may improve the viscosity stability of the fluid as awhole. Suitable glycols for use with the stabilizing method hereininclude, but are not necessarily limited to, monoethylene glycol (MEG),diethylene glycol (DEG), triethylene glycol (TEG), tetraethylene glycol(TetraEG), monopropylene glycol (MPG), dipropylene glycol (DPG), andtripropylene glycol (TPG), and where the polyols include, but are notnecessarily limited to, polyethylene glycol (PEG), polypropylene glycol(PPG), and glycerol and other sugar alcohols, and mixtures thereof. Inthe case where the stabilizer is a polyol, the molecular weight of thepolyol may range from about 54 to about 370 weight average molecularweight, alternatively where the lower threshold is about 92 weightaverage molecular weight, and/or where the upper threshold is about 235weight average molecular weight. Suitable proportions of glycols orpolyol stabilizers that may be used, introduced or added, in onenon-limiting embodiment, range from about 0.1 to 10.0% by volume basedon the total of the aqueous fluid. In an alternate, non-restrictiveembodiment, the lower end of this proportion range may be about 0.2% by,and additionally or alternatively the upper end of this proportion rangemay be about 5.0% by. Further details about polyol and/or glycolstabilizers may be found in U.S. Patent Application Publication No.2007/0244015 A1, incorporated herein in its entirety by reference.

In a useful, non-restrictive embodiment herein, use with internal VESbreakers can have synergistic clean-up effects for the fluid losscontrol agent and the VES fluid. Use of these compositions with aninternal breaker may allow less VES fluid to leak-off into thereservoir, thus resulting in less fluid needed to be broken and removedonce the treatment is over. Additionally, use of an internal breakerwithin the VES micelles may further enhance the breaking and removal ofthe pseudo-filter cake viscous VES layer that develops on the formationface with the fluid loss agents herein. Lab tests to date appear to showthat the viscous VES pseudo-filter cake has the micelles readily brokendown to the relatively non-viscous, more spherically-shaped micelles byuse of an internal breaker, and also with use of encapsulated breaker,if used.

The invention will now be further illustrated with respect to particularExamples which are not intended to limit the invention in any regard,but instead are intended to further describe and illuminate certainnon-restrictive embodiments of the invention.

Example 1

Shown in FIG. 1 is a top view schematic illustration of a wellbore 10with a schematic portrayal of a hydraulic fracture 11 extending inopposite directions (to the left and right of FIG. 1), where portions12A are the near-wellbore sections of hydraulic fracture 11 and portions12B are the near tip sections of hydraulic fracture 11. The area withinoval-shaped region 14A represents the area of wellbore 10 and hydraulicfracture 11 commonly treated when placing a non-diverting treatmentfluid is used to clean up the well, or when chemicals are placed withinthe hydraulic fracture 11; the edge of the area treated by thenon-diverting treatment fluid is seen at 14B. It may be seen that someof the treatment fluid extends transverse to the fracture 11 (up anddown, as seen in FIG. 1), and more significantly that large portions ofhydraulic fracture 11, particularly the near tip sections 12B, are nottreated.

Shown in FIG. 2 is the top view schematic illustration of a wellbore 10and hydraulic fracture 11, where a delayed release treatment fluidhaving pseudo-crosslinked fluid loss control as described herein hasbeen injected into the wellbore 10 and fracture 11. The gray portion 15Ais a schematic diagram of the area of the hydraulic fracture 11 that istreated with this treatment fluid, where the edge of the gray area 15Atreated with the delayed release treatment fluid is designated at 15B.It may be seen that due to the diverting nature of the treatment fluiddescribed herein having pseudo-crosslinked micelles, the fluid extendsthe entire length of the hydraulic fracture to the near tip sections 12Band is not spent into the reservoir in the transverse direction indictedby area 14A and edge 14A.

Example 2

Shown in FIG. 3 is a cross-sectional, elevation view of hydraulicfracture and treatment fluid placements around a wellbore, where 50 isthe top section of the wellbore, 51 is the bottom section of thewellbore, 52′ and 52″ represent the upper and lower boundaries,respectively, of the hydrocarbon-bearing reservoir 52 and the nearwellbore section of the hydraulic fracture is shown at 53. Presentwithin hydrocarbon-bearing reservoir 52 is an upper high permeabilitystreak 54 and a lower high permeability streak 55 (which happens to beshown as deeper than upper streak 54, in this non-limiting Example).Reservoir 52 has been fractured along upper high permeability streak 54as shown by upper section 56 of the hydraulic fracture and fracturedalong lower high permeability streak 55 as shown by lower section 57 ofthe hydraulic fracture. The white area 58 schematically illustrates theupper area where a conventional treatment fluid is placed and relativelylarger white area 59 schematically illustrates the lower area where aconventional treatment fluid is placed.

Shown in FIG. 4 is the cross-sectional, elevation view of hydraulicfracture of FIG. 3 where gray area 60 schematically illustrates theupper section of the placement of the delayed release treatment fluid asdescribed herein. Similarly, gray area 61 schematically illustrates thelower section of the placement of the delayed release treatment fluid asdescribed herein. These gray areas 60 and 61 show near complete coverageof the upper section 56 and lower section 57 of the hydraulic fracture,respectively, for the upper high permeability streak 54 and lower highpermeability streak 55. It may be seen that coverage using the delayedrelease treatment fluids described herein is expected to be much greaterthan for conventional treatment fluids. FIGS. 3 and 4 herein are roughlycomparable to FIGS. 1 and 2 previously described, but from an elevationpoint of view, rather than from above.

Example 3

Shown in FIG. 5 is a cross-sectional, perspective view of a hydraulicfracture and treatment fluid placement around a wellbore, where 20 isthe top section of the wellbore, 21 is the bottom section of thewellbore, 22′ and 22″ represent the upper and lower boundaries,respectively, of the hydrocarbon-bearing reservoir 22 and the nearwellbore section of the hydraulic fracture is shown at 23. The largerfracture 24 has an edge periphery 25. The first potential area aroundthe immediate wellbore area and hydraulic fracture 24 where typicalnon-diverting treatment fluids are placed is shown at 26, where the edgeof this area is shown at 27. A second potential area of wellbore andhydraulic fracture 24 where a typical non-diverting treatment fluid isplaced is shown at 28, where the edge of this area is shown at 29. Theseareas are generally understood to be considerably less in volume thanthe entire area of fracture 24 and its boundary 25.

Shown in FIG. 6 is the cross-sectional, perspective view of hydraulicfracture of FIG. 5 where gray area 30 schematically illustrates thepotential area along fracture 24 where the delayed release treatmentfluid as described herein may occur, where the edge 31 of this region 30demonstrates nearly complete coverage of the fracture section 24 nearlyto edge 25. FIG. 6 illustrates that the potential area 30 extends widerthan first potential area 26 and deeper than second potential area 28.Thus, the delayed release treatment fluids described herein are expectedto be more effective than conventional treatment fluids since they willmore fully extend through and treat more of the hydraulic fracture inwhich they are placed.

In the foregoing specification, the invention has been described withreference to specific embodiments thereof as effective in deliveringchemicals, particles, and other agents downhole using viscoelasticsurfactant gelled fluids. However, it will be evident that variousmodifications and changes can be made thereto without departing from thebroader spirit or scope of the invention as set forth in the appendedclaims. Accordingly, the specification is to be regarded in anillustrative rather than a restrictive sense. For example, specificcombinations of brines, viscoelastic surfactants, internal breakers andchemicals, particles and other agents, and other components fallingwithin the claimed parameters, but not specifically identified or triedin a particular composition, are anticipated to be within the scope ofthis invention.

The present invention may suitably comprise, consist or consistessentially of the elements disclosed and may be practiced in theabsence of an element not disclosed.

The words “comprising” and “comprises” as used throughout the claims,are to be interpreted to mean “including but not limited to” and“includes but not limited to”, respectively.

What is claimed is:
 1. An aqueous viscoelastic treating fluidcomprising: an aqueous base fluid; a viscoelastic surfactant (VES)gelling agent in an amount effective to form a VES gel that increasesthe viscosity of the aqueous viscoelastic surfactant treating fluid; atleast one internal breaker within the VES gel, where the internalbreaker is selected from the group consisting of mineral oils, fishoils, hydrogenated polyalphaolefin oils, transition metal ion sources,reducing agent sources, chelating agent sources, alkali metal sources,alkaline earth metal sources, saponified fatty acids, unsaturated orsaturated fatty acids, and combinations thereof; an agent within the VESgel, where the agent is selected from the group consisting of fluid losscontrol agents, bacteria, enzyme polymer breakers, oxidative polymerbreakers, polymer breaker enhancers, microencapsulated chemicals,macroencapsulated chemicals, nanoencapsulated chemicals, scaleinhibitors, gas hydrate inhibitors, stimulation chemicals, remedialcleanup agents, water-block removal agents, crosslinkers, polymers,biocides, corrosion inhibitors, corrosion dissolvers, pH modifiers,metal chelators, metal complexors, antioxidants, wetting agents, polymerstabilizers, clay stabilizers, scale dissolvers, wax inhibitors, waxdissolvers, asphaltene precipitation inhibitors, waterflow inhibitors,sand consolidation chemicals, permeability modifiers, foaming agents,microorganisms, nutrients for microorganisms, fine migration controlagents, zeolites, clays, inorganic flakes, ceramics, cement, activatedcarbon, surfactants, paraffin inhibitors, oxygen scavengers, amines, pHbuffers, friction reducers, clay inhibitors, production chemicals,diverting agents, diverting agents and salts thereof and combinationsthereof; and a component selected from the group consisting of atemperature stabilizer, a viscosity stabilizer, a viscosity enhancer,and combinations thereof.
 2. The aqueous viscoelastic treating fluid ofclaim 1 where the aqueous base fluid is brine.
 3. The aqueousviscoelastic treating fluid of claim 1 where a fluid loss control agentis present at a concentration effective to improve the fluid loss of theaqueous viscoelastic treating fluid as compared with an identical fluidabsent the fluid loss control agent, where the fluid loss control agentis selected from the group consisting of alkaline earth metal oxides,alkaline earth metal hydroxides, transition metal oxides, transitionmetal hydroxides, and mixtures thereof.
 4. The aqueous viscoelastictreating fluid of claim 3 where in the fluid loss control agent, thealkaline earth metal oxide or hydroxide is selected from the groupconsisting of oxides or hydroxides of magnesium, calcium, strontium,barium and mixtures thereof, and the transition metal oxide or hydroxideis selected from the group consisting of oxides or hydroxides ofaluminum, zirconium, vanadium, molybdenum, manganese, iron, cobalt,nickel, palladium, copper, zinc, tin, antimony, titanium andcombinations thereof.
 5. The aqueous viscoelastic treating fluid ofclaim 3 where the effective concentration of the fluid loss controlagent ranges from about 2 to about 200 pptg (about 0.2 to about 24kg/m³) based on the aqueous viscoelastic treating fluid.
 6. The aqueousviscoelastic treating fluid of claim 1 where the agent is a solid andhas a size ranging from about 1 nanometer to about 10 millimeters. 7.The aqueous viscoelastic treating fluid of claim 1 where the agent is aliquid.
 8. An aqueous viscoelastic treating fluid comprising: a brinebase fluid; a viscoelastic surfactant (VES) gelling agent in an amounteffective to form a VES gel that increases the viscosity of the aqueousviscoelastic surfactant treating fluid; at least one internal breakerwithin the VES gel, where the internal breaker is selected from thegroup consisting of mineral oils, fish oils, hydrogenatedpolyalphaolefin oils, transition metal ion sources, reducing agentsources, chelating agent sources, alkali metal sources, alkaline earthmetal sources, saponified fatty acids, unsaturated or saturated fattyacids, and combinations thereof; an agent within the VES gel, where theagent is a solid and has a size ranging from about 1 nanometer to about10 millimeters, and is selected from the group consisting of fluid losscontrol agents, enzyme polymer breakers, oxidative polymer breakers,polymer breaker enhancers, microencapsulated chemicals,macroencapsulated chemicals, nanoencapsulated chemicals, scaleinhibitors, gas hydrate inhibitors, stimulation chemicals, remedialcleanup agents, water-block removal agents, crosslinkers, polymers,biocides, corrosion inhibitors, corrosion dissolvers, pH modifiers,metal chelators, metal complexors, antioxidants, wetting agents, polymerstabilizers, clay stabilizers, scale dissolvers, wax inhibitors, waxdissolvers, asphaltene precipitation inhibitors, waterflow inhibitors,sand consolidation chemicals, permeability modifiers, foaming agents,nutrients for microorganisms, fine migration control agents, zeolites,clays, inorganic flakes, ceramics, cement, activated carbon,surfactants, paraffin inhibitors, oxygen scavengers, amines, pH buffers,friction reducers, clay inhibitors, production chemicals, divertingagents, diverting agents and salts thereof and combinations thereof; anda component selected from the group consisting of a temperaturestabilizer, a viscosity stabilizer, a viscosity enhancer, andcombinations thereof.
 9. The aqueous viscoelastic treating fluid ofclaim 8 where the agent comprises a fluid loss control agent is presentat a concentration effective to improve the fluid loss of the aqueousviscoelastic treating fluid as compared with an identical fluid absentthe fluid loss control agent, where the fluid loss control agent isselected from the group consisting of alkaline earth metal oxides,alkaline earth metal hydroxides, transition metal oxides, transitionmetal hydroxides, and mixtures thereof.
 10. The aqueous viscoelastictreating fluid of claim 8 where a fluid loss control agent is present ata concentration effective to improve the fluid loss of the aqueousviscoelastic treating fluid as compared with an identical fluid absentthe fluid loss control agent, where the fluid loss control agent isselected from the group consisting of alkaline earth metal oxides,alkaline earth metal hydroxides, transition metal oxides, transitionmetal hydroxides, and mixtures thereof.
 11. The aqueous viscoelastictreating fluid of claim 10 where in the fluid loss control agent, thealkaline earth metal oxide or hydroxide is selected from the groupconsisting of oxides or hydroxides of magnesium, calcium, strontium,barium and mixtures thereof, and the transition metal oxide or hydroxideis selected from the group consisting of oxides or hydroxides ofaluminum, zirconium, vanadium, molybdenum, manganese, iron, cobalt,nickel, palladium, copper, zinc, tin, antimony, titanium andcombinations thereof.
 12. The aqueous viscoelastic treating fluid ofclaim 10 where the effective concentration of the fluid loss controlagent ranges from about 2 to about 200 pptg (about 0.2 to about 24kg/m³) based on the aqueous viscoelastic treating fluid.
 13. An aqueousviscoelastic treating fluid comprising: a brine aqueous base fluid; aviscoelastic surfactant (VES) gelling agent in an amount effective toform a VES gel that increases the viscosity of the aqueous viscoelasticsurfactant treating fluid; at least one internal breaker within the VESgel, where the internal breaker is selected from the group consisting ofmineral oils, fish oils, hydrogenated polyalphaolefin oils, transitionmetal ion sources, reducing agent sources, chelating agent sources,alkali metal sources, alkaline earth metal sources, saponified fattyacids, unsaturated or saturated fatty acids, and combinations thereof;an agent within the VES gel, where the agent is selected from the groupconsisting of fluid loss control agents, bacteria, enzyme polymerbreakers, oxidative polymer breakers, polymer breaker enhancers,microencapsulated chemicals, macroencapsulated chemicals,nanoencapsulated chemicals, scale inhibitors, gas hydrate inhibitors,stimulation chemicals, remedial cleanup agents, water-block removalagents, crosslinkers, polymers, biocides, corrosion inhibitors,corrosion dissolvers, pH modifiers, metal chelators, metal complexors,antioxidants, wetting agents, polymer stabilizers, clay stabilizers,scale dissolvers, wax inhibitors, wax dissolvers, asphalteneprecipitation inhibitors, waterflow inhibitors, sand consolidationchemicals, permeability modifiers, foaming agents, microorganisms,nutrients for microorganisms, fine migration control agents, zeolites,clays, inorganic flakes, ceramics, cement, activated carbon,surfactants, paraffin inhibitors, oxygen scavengers, amines, pH buffers,friction reducers, clay inhibitors, production chemicals, divertingagents, diverting agents and salts thereof and combinations thereof; acomponent selected from the group consisting of a temperaturestabilizer, a viscosity stabilizer, a viscosity enhancer, andcombinations thereof; and a fluid loss control agent is present at aconcentration effective to improve the fluid loss of the aqueousviscoelastic treating fluid as compared with an identical fluid absentthe fluid loss control agent, where the fluid loss control agent isselected from the group consisting of alkaline earth metal oxides,alkaline earth metal hydroxides, transition metal oxides, transitionmetal hydroxides, and mixtures thereof.
 14. The aqueous viscoelastictreating fluid of claim 13 where in the fluid loss control agent, thealkaline earth metal oxide or hydroxide is selected from the groupconsisting of oxides or hydroxides of magnesium, calcium, strontium,barium and mixtures thereof, and the transition metal oxide or hydroxideis selected from the group consisting of oxides or hydroxides ofaluminum, zirconium, vanadium, molybdenum, manganese, iron, cobalt,nickel, palladium, copper, zinc, tin, antimony, titanium andcombinations thereof.
 15. The aqueous viscoelastic treating fluid ofclaim 13 where the effective concentration of the fluid loss controlagent ranges from about 2 to about 200 pptg (about 0.2 to about 24kg/m³) based on the aqueous viscoelastic treating fluid.
 16. The aqueousviscoelastic treating fluid of claim 13 where the agent is a solid andhas a size ranging from about 1 nanometer to about 10 millimeters. 17.The aqueous viscoelastic treating fluid of claim 13 where the agent is aliquid.